How to Finance Commercial Solar in Africa: Capex, Lease and PPA Compared

Most businesses that decide against solar do not decide against solar. They decide against writing a large cheque this quarter.

The engineering case is usually settled quickly. A factory manager looking at a diesel bill can do the arithmetic in an afternoon and reach the obvious conclusion. What stops the project is that the capital sits in one budget year while the savings arrive across ten, and the finance director has three other calls on the same money that produce revenue rather than reduce cost.

This is a financing problem, not a technology problem, and it has several solutions. Commercial solar financing in Africa now runs across four broad structures, each with a genuinely different risk profile, tax treatment and cost of capital. Choosing badly is expensive in ways that are not visible at signature.

This article sets out the four structures, what each actually costs, how currency exposure reshapes the comparison in Nigeria, Egypt and Sudan, and the specific contract terms that determine whether the deal works.

Why the Comparison Is Against Diesel, Not the Grid

Before the financing question, the benchmark needs setting correctly, because getting it wrong makes every subsequent calculation meaningless.

For most commercial and industrial sites in this region, the relevant comparison is not solar against grid tariff. It is solar against the blended cost of the electricity the business actually consumes, which is some mixture of grid supply where available and self-generated diesel power where it is not.

That blend is what makes the numbers work. Industry analysis of the African commercial and industrial market puts the tariff for financed captive solar in the range of roughly $0.08 to $0.12 per kilowatt-hour, against backup diesel generation costing in the order of $0.35 to $0.40 per kilowatt-hour. The gap is not marginal. It is a multiple.

Meanwhile the underlying cost of the technology has continued to fall. IRENA's cost tracking documents the sustained decline in utility-scale and distributed solar costs that has made these structures financeable at all, and the IEA's Africa Energy Outlook sets out how much of the continent's industrial demand is currently met by self-generation.

Any financing decision should therefore start from a measured baseline: what the business currently pays per kilowatt-hour, all in, including fuel, generator maintenance, generator replacement reserve and the production lost to outages. Our solar payback calculator produces that comparison quickly, and our guide to commercial solar installation costs in Nigeria breaks down what the capital number is actually made of.

Structure One: Direct Purchase

The business buys the system outright and owns it from day one.

What it costs. The full capital sum up front, plus operations and maintenance thereafter. The effective cost per kilowatt-hour over the asset's life is the lowest of any structure, because nobody is charging a margin for taking financing risk.

What it delivers. Complete ownership of the savings. Every kilowatt-hour the array produces for the next twenty-five years belongs to the business. Any capital allowance or accelerated depreciation available in the jurisdiction accrues to the owner. There is no counterparty to negotiate with about system expansion, roof works or eventual sale of the premises.

What it demands. Capital that could be deployed elsewhere, and the technical competence to specify and accept the system, because there is no financier performing due diligence on your behalf. This is the structure with the highest exposure to poor engineering: a business that buys badly owns the consequences alone.

When it fits. Cash-generative businesses with a low internal cost of capital, where the return on solar comfortably beats the alternative use of the money, and where the site is owned rather than leased. It is by some distance the cheapest option if the capital exists.

Structure Two: Debt-Financed Purchase

The business still owns the asset, but funds it with a bank loan, an asset finance facility or a development finance line.

What it costs. Capital cost plus interest over the tenor. In practice the tenor is the critical variable. A facility repayable over three years against an asset producing for twenty-five compresses the repayment into a period where it may exceed the energy saving, which converts a cash-positive project into a cash-negative one for the first few years even though the underlying economics are sound.

What it delivers. Ownership, with its tax and residual value benefits, without the up-front cash outlay.

What it demands. Balance sheet capacity and a lender that understands the asset. Where local banks will lend against solar as productive equipment with a matched tenor, this is frequently the best structure available. Where the only facility on offer is a short-tenor working capital loan, it is often worse than a PPA despite the lower headline cost of capital. Development finance institutions and green credit lines increasingly offer longer tenors specifically to address this mismatch.

When it fits. Businesses that want ownership, have banking relationships, and can secure a tenor that reasonably matches the asset life. The rule of thumb is straightforward: if annual debt service exceeds annual energy saving, the structure is wrong even if the project is right.

Weighing structures against your actual load and tariff? Our renewable energy team builds the technical case that any of these financing routes has to be underwritten against.

The four financing structures compared on the three variables that decide the outcome: capital outlay, ownership, and who carries performance risk. Source: MIMAH engineering and commercial analysis.

Structure Three: Lease

A financier owns the equipment and leases it to the business for a fixed periodic payment, usually with a purchase option at the end of the term.

What it costs. A fixed payment regardless of how much energy the system produces. This is the defining characteristic and it cuts both ways.

What it delivers. Predictable cost, no capital outlay, and often an operating lease treatment that keeps the asset off balance sheet, which some businesses value for their own reasons. Where the system outperforms expectations, the additional energy is free to the lessee because the payment does not change.

What it demands. Acceptance of performance risk. If the system underperforms, whether through poor design, poor maintenance or a shaded roof nobody surveyed, the lease payment continues unchanged. This is the exact opposite of the PPA risk allocation, and it is why lease structures require the technical due diligence to be done by the lessee rather than assumed.

When it fits. Businesses that want predictable payments, are confident in the system's design and the installer's competence, and value the balance sheet treatment. It works best where the lessee retains a strong O&M arrangement, because under a lease the incentive to maintain the system sits entirely with the party paying regardless.

Structure Four: The Power Purchase Agreement

A developer funds, builds, owns, operates and maintains the system on the customer's site, and the customer buys the electricity it produces at an agreed tariff for an agreed term. This is the structure that has done most to open the African commercial and industrial market.

What it costs. A tariff per kilowatt-hour, typically escalating at a defined annual rate, over a term commonly between ten and twenty years. The effective cost of capital is the highest of the four structures, because the developer is taking construction risk, performance risk, operating risk and offtaker credit risk, and is pricing all of it.

What it delivers. No capital outlay whatsoever, and a genuine transfer of performance risk. The customer pays for energy delivered. If the system underproduces, the customer pays less. If it fails entirely, the customer pays nothing and the developer has a serious problem. That alignment is the PPA's core virtue: the party responsible for the engineering is the party who suffers when the engineering is wrong.

What it demands. A site the customer will occupy for the term, a credit profile the developer will accept, and careful attention to the contract. A twenty-year agreement signed in a hurry is a twenty-year problem.

When it fits. Businesses without capital, businesses that want the performance risk carried by someone else, and businesses whose credit is strong enough to attract a competitive tariff. It is also frequently the fastest route from decision to commissioned system, because the developer's own capital and processes are already mobilised.

Tariff for financed captive solar against the cost of backup diesel generation for African commercial and industrial customers. Source: Solar PV Powering the Commercial and Industrial Sector in Africa, Synergy Consulting.

Currency Is the Risk Nobody Prices Correctly

Any financing discussion in this region that ignores currency is incomplete, and it is where deals that looked sound go wrong.

Solar equipment is imported and priced in hard currency. Modules, inverters, batteries and drives are bought in dollars or euros. A business in Nigeria, Egypt or Sudan earns in local currency. That mismatch has been brutally demonstrated in recent years: the naira lost a very large share of its value through the liberalisation of 2023 and 2024, and the Egyptian pound broke its managed peg in March 2024.

The consequences depend on the structure.

Under a direct purchase, the currency risk is taken once, at the point of procurement, and then it is over. The business has converted local currency into a hard asset that produces energy for twenty-five years and has no further foreign exchange exposure. In a depreciating currency environment, this is a genuinely powerful hedge: the business has pre-purchased two decades of electricity at today's exchange rate.

Under a dollar-denominated PPA, the risk runs for the whole term. The customer's obligation is in hard currency and their revenue is in local currency, so every devaluation increases the real cost of their electricity. A tariff that looked attractive at signature can become punishing after a currency adjustment, and this has caused real distress in real contracts.

Under a local-currency PPA, the developer takes the risk instead, and prices it into the tariff. The headline number is higher, and it is genuinely higher for a reason, because somebody has to bear the exposure. Whether that is worth paying for depends on the business's own view of its currency.

The practical guidance is simple to state and frequently ignored. Read which currency the obligation is denominated in, and what escalation mechanism applies. Model the deal under a significant devaluation, not just under the base case. A local-currency PPA at a higher tariff is often cheaper in expectation than a dollar PPA at a lower one, and businesses that learned this in 2024 learned it the hard way.

The Contract Terms That Actually Decide the Outcome

Whatever structure is chosen, a small number of provisions determine whether the arrangement works over its life.

Performance guarantee and the remedy. A PPA or lease should specify guaranteed annual production, adjusted for actual irradiance, with a defined financial remedy if it is missed. A guarantee with no remedy is a statement of intent.

Escalation. A tariff escalating at a fixed annual percentage will eventually diverge from the alternative. Model the tariff to the final year and compare it against a realistic view of grid and diesel costs then, not just against today.

Term and early termination. Termination values in the early years of a PPA can be very high, because the developer's capital has not yet been recovered. A business that may relocate, expand substantially, or sell the premises needs to know precisely what exit costs before signing.

End-of-term arrangements. What happens in year twenty-one? Transfer to the customer at nominal value, extension at a renegotiated tariff, or removal. Each has very different value, and the asset at that point still has years of production ahead.

Roof and site rights. Who is responsible if the roof needs work? Who bears the cost of removing and reinstating the array? Who insures the equipment, and against what? These are ordinary questions and they cause extraordinary disputes when unanswered.

Curtailment and minimum offtake. Many PPAs oblige the customer to take, or pay for, all energy the system produces. A business whose production drops, or which closes for a seasonal shutdown, can find itself paying for energy it did not use. Understand this clause before signing rather than during a downturn.

Maintenance obligations and standards. Under a PPA the developer maintains the system because their revenue depends on it. Under a purchase or lease, maintenance is the owner's or lessee's problem, and it must be contracted explicitly with defined response times and reporting.

Assessing a PPA offer or a lease proposal? Talk to our engineering team before signing. We review the technical assumptions behind the financial model, which is where most of the risk actually sits. Our project portfolio documents commercial, industrial and institutional systems across multiple countries.

Where the foreign exchange risk sits under each structure. Equipment is imported and priced in hard currency; revenue is earned locally. Source: MIMAH commercial analysis.

Where Donor and Development Finance Changes the Picture

For agricultural, health, water and rural energy applications, a fifth route exists that does not fit the commercial framing at all.

Development banks, bilateral donors and United Nations agencies fund solar deployment through grants, concessional lending and results-based financing, in which payment is released against verified connections, verified installations or verified service delivery rather than against invoices. This structure has become dominant in rural electrification and in agricultural mechanisation programmes, and it changes the economics fundamentally, because a large share of the capital does not need recovering from the end user at all.

The trade-off is process. These programmes carry procurement requirements, technical standards, reporting obligations and verification regimes that a commercial deal does not, and they run on timelines set by institutions rather than by businesses. Organisations that can meet those requirements gain access to capital at a cost no commercial structure can match. Organisations that cannot should not shape their plans around it.

This route is particularly relevant for solar irrigation, covered in our solar water pumping guide, and for rural electrification, covered in our guide to solar mini-grids, where results-based financing has become the standard mechanism for closing the affordability gap.

Frequently Asked Questions

Which financing structure is cheapest overall? Direct purchase, by a clear margin, because no one is charging for taking risk. The relevant question is not which is cheapest in absolute terms but which delivers the best return given your cost of capital and what else the money could do. A business earning a strong return on working capital may be right to choose a PPA even though it costs more per kilowatt-hour.

Can a business get a solar PPA without a strong credit rating? It is harder and more expensive. Developers are lending against future payments, so offtaker credit drives the tariff. Options for weaker credits include shorter terms, security arrangements, partial prepayment, guarantees from a parent company, or a lease structure where the financier holds title to the equipment as security.

Should the PPA be in dollars or local currency? Local currency is usually safer for a business earning in local currency, even at a higher headline tariff, because the alternative exposes you to devaluation for the entire term. The right way to decide is to model both under a significant devaluation scenario rather than comparing headline tariffs.

What happens to a PPA if we sell the building? The agreement normally transfers to the new owner, subject to their acceptance and often to the developer's approval of their credit. If they refuse, termination provisions apply, and those can be expensive in early years. Check the assignment clause before signing if a sale is conceivable.

Do the tax benefits of ownership matter? They can matter substantially where capital allowances or accelerated depreciation are available on renewable equipment, and they accrue only under purchase or finance lease structures, not under a PPA. Rules vary by country and change, so this needs checking locally rather than assumed.

How long do these agreements typically run? PPAs commonly run ten to twenty years, matched to the asset's productive life and to the developer's capital recovery. Leases are usually shorter, frequently five to ten. Debt facilities depend entirely on what local lenders offer, and tenor mismatch against asset life is the most common problem with this route.

The Structure Should Follow the Balance Sheet

There is no universally correct answer, and any adviser who names one without looking at your accounts is selling something.

A cash-rich manufacturer with a twenty-year lease on its premises and an appetite for capital allowances should almost certainly buy. A fast-growing business with better uses for every naira of working capital and no engineering staff should probably sign a PPA and transfer the performance risk. A business with a good bank relationship and access to a matched-tenor facility can often own the asset while paying for it out of the savings it generates.

What all of them need first is the same thing: a measured baseline of what they currently pay per kilowatt-hour, an honest engineering assessment of what a system on that site will produce, and a clear view of the currency the obligation is written in. Get those three right and the financing structure follows from the balance sheet. Get them wrong and the cleverest structure in the world is built on a number that was never true.

Want the technical case built before you take a financing decision? Talk to our engineering team. We will measure the load, model the production and give you the figures any of these structures has to be tested against.